Acidic internal breaker for viscoelastic surfactant fluids in brine

ABSTRACT

Compositions and methods are given for delayed breaking of viscoelastic surfactant gels inside formation pores, particularly for use in hydraulic fracturing. Breaking inside formation pores is accomplished without mechanical intervention or use of a second fluid. Acidic internal breakers such as sulfuric acid and nitric acid are used. The break may be accelerated, for example with a free radical propagating species, or retarded, for example with an oxygen scavenger.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application a divisional application of U.S. patent applicationSer. No. 11/770,442, filed Jun. 6, 2007 now issued as U.S. Pat. No.7,635,028, which is a continuation-in-part of copending application Ser.No. 11/532,565, entitled “Oxidative Internal Breaker for ViscoelasticSurfactant Fluids”, filed Sep. 18, 2006, issued as U.S. Pat. No.7,879,770. This application is related to copending application entitled“Oxidative Internal Breaker System with Breaking Activators forViscoelastic Surfactant Fluids”, filed Jun. 28, 2007 (Ser. No.11/770,313, published as US2008/0070806). The application is alsorelated to copending application Ser. No. 11/532,553, entitled “InternalBreaker for Oilfield Treatments,” inventors Jesse Lee, Philip Sullivan,Erik Nelson, Yiyan Chen, Carlos Abad, Belgin Baser, and Lijun Lin, filedSep. 18, 2006, issued as U.S. Pat. No. 7,677,311. This application isrelated to copending application Ser. No. 11/532,559, entitled “InternalBreaker for Oilfield Fluids,” inventors Philip Sullivan, Yiyan Chen,Belgin Baser, Carlos Abad, Mehmet Parlar, and Gregory Kubala, filed Sep.18, 2006, issued as U.S. Pat. No. 7,287,590. This application is alsorelated to copending application Ser. No. 11/532,705, entitled “Methodfor Limiting Leakoff and Damage in Hydraulic Fractures,” inventorsRichard Hutchins, Marie Dessinges, and Carlos Abad, filed Sep. 18, 2006,issued as U.S. Pat. No. 7,398,829. These applications are all assignedto the assignee of the present application and are hereby incorporatedin their entirety.

BACKGROUND OF THE INVENTION

The invention relates to recovery of oil and gas from wells, and moreparticularly to breaking fluids inside formation pores when usingviscoelastic surfactant fluid systems (VES's) as carrier fluids andtreatment fluids.

There are many applications in which breakers are needed to decrease theviscosity of treatment fluids, such as fracturing, gravel packing, andacidizing fluids, viscosified with polymers or crosslinked polymers orviscoelastic surfactants. Most commonly, these breakers act in fluidsthat are in gravel packs or fractures; some breakers can work in fluidsin formation pores. Breakers decrease viscosity by degrading polymers orcrosslinks when the viscosifiers are polymers or crosslinked polymers.Breakers decrease viscosity by degrading surfactants or destroyingmicelles when viscosifiers are viscoelastic surfactant fluid systems.Breakers can be solids, for example granules or encapsulated materials,that do not enter the formation.

There is sometimes a need to break viscous fluids within the pores offormations, for example when viscous fluids enter formations duringfracturing, gravel packing, acidizing, matrix dissolution, lostcirculation treatments, scale squeezes, and the like. Breakers that areeffective inside formations will be called internal breakers here. Thesefluids that enter the formation may be main treatment fluids (such asfracturing fluids) or they may be secondary fluids (such as flushes ordiversion fluids such as viscoelastic diverting acids). Typically it isnecessary that the break be delayed, that is that the breaker not actuntil after the fluid has performed its function.

The current practice to improve clean-up of VES fluids in matrices is touse pre-flush or post-flush fluids to dilute the system or to contactthe system with a breaker. The major disadvantage of the use pre-flushor post-flush fluids is their limited interaction with the VES fluid dueto the small interface between the two fluids. The efficiency of thisbreaking mechanism depends upon diffusion, which is slow in highlyviscous fluids. Furthermore, the volumes of the flushes can be high.

Compositions and treatment methods using a delayed internal breaker,that acts without mechanical or chemical action by the operator, wouldbe of value. It would be desirable to have a number of such materials sothat they could be used under different subterranean conditions, forexample different temperatures and different formation fluidchemistries.

It has now been discovered that certain acids or the combinations ofcertain salt(s) and acid(s) will perform as internal breakers and willallow fluid design with pre-selectable timing for breaking of the fluid.

SUMMARY OF THE INVENTION

The composition of the invention is an oilfield treatment compositioncontaining an aqueous fluid, a non-polymeric viscosifier and an acidicmaterial or compound.

In one embodiment, the composition comprises an oilfield treatmentcomposition containing an aqueous fluid, a non-polymeric viscosifier andan acidic internal breaker in brines that contain substantially nodivalent cations, such as magnesium ion, zinc ions or calcium ion(Ca²⁺). Useful acidic internal breakers for such brines include sulfuricacid, nitric acid, sulfates in combination with acids, and nitrates incombination with acids.

In another embodiment, the composition comprises a non-polymericviscosifier and an acidic internal breaker in an oilfield treatmentcomposition containing an aqueous fluid, a non-polymeric viscosifier anda brine which contain divalent cations such as Ca²⁺, Mg²⁺ or Zn²⁺.Useful acidic internal breakers for these fluids include, but notlimited to nitric acid, nitrates in combination with acids, hydrochloricacid, acetic acid, and chloride or acetates with acids.

In yet another embodiment, the non-polymeric viscosifier is aviscoelastic surfactant, for example a zwitterionic surfactant, forexample a betaine, or an amidoamine oxide.

In another embodiment, the oilfield treatment composition furthercomprises a corrosion inhibitor. Such inclusion will protect theformation and equipment from the corrosive properties of the acidicbreaker as well as any other corrosive ingredient.

Another embodiment of the invention is a method of treating asubterranean formation penetrated by a wellbore comprising a) injectinginto the pores of the formation an aqueous gel comprising anon-polymeric viscosifier, an acidic internal breaker soluble in thegel, and b) allowing said gel to lose viscosity gradually in the poresafter the injection.

Another embodiment is a method of treating a subterranean formationpenetrated by a wellbore comprising a) injecting into the pores of theformation an aqueous gel comprising a non-polymeric viscosifier, anacidic internal breaker soluble in the gel, wherein said breaker isselected from the group consisting of certain mineral acids, and b)allowing said gel to lose viscosity gradually in the pores after theinjection.

Another embodiment is a method of treating a subterranean formationpenetrated by a wellbore comprising a) injecting into the pores of theformation an aqueous gel comprising a non-polymeric viscosifier, anacidic internal breaker soluble in the gel, wherein said breaker isselected from the group consisting of certain organic acids and latentacids, and b) allowing said gel to lose viscosity gradually in the poresafter the injection.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows the viscosity vs. time of a base VES fluid containing 1.39kg/L CaCl2 brine, 6.5 vol % aqueous solution of erucic amidopropyldimethyl betaine, and 0.2 vol % 2-Butoxyethanol with no additives.

FIG. 2 shows the viscosity vs. time of a VES fluid containing 1.43 kg/LNaBr brine, 6.5 vol % of an aqueous solution of erucic amidopropyldimethyl betaine, and 0.2 vol % 2-Butoxyethanol, containing a sulfuricacid internal breaker (3M sulfuric acid solution) at concentrations of0, 0.1 vol %, and 0.15 vol %, respectively at 104° C. (219° F.).

FIG. 3 shows the viscosity vs. time of the base VES fluid containing1.43 kg/L NaBr brine, 6.5 vol % aqueous solution of erucic amidopropyldimethyl betaine, and 0.2 vol % aqueous solution of alkyl (C12-16)dimethyl benzyl ammonium chloride containing the internal breaker (3Msulfuric acid solution) at concentrations of 0.075 vol % and 0.1 vol %,respectively, at 104° C. (219° F.).

FIG. 4 shows the viscosity versus time of a gel containing 1.43 kg/LNaBr and 8 vol % aqueous solution of erucic amidopropyl dimethylbetaine, containing the sulfuric acid internal breaker (3M sulfuric acidsolution) at concentrations of 0, 0.11 vol %, and 0.15 vol %,respectively, at 104° C. (219° F.).

FIG. 5 shows the viscosity as a function of shear rate for a VES fluidcontaining 1.43 kg/L NaBr and 8 vol % aqueous solution of erucicamidopropyl dimethyl betaine, containing 0 and 0.11 vol % of 3M sulfuricacid solution as the internal breaker at RT and 93° C. (200° F.),respectively.

FIG. 6 shows the viscosity as a function of time at for VES fluidscontaining 1.43 kg/L NaBr and 6 vol % aqueous solution of erucicamidopropyl dimethyl betaine, containing the internal breaker(D-isoascorbic acid) at concentrations of 0.10 wt % and 0.25 wt %,respectively at 93.3° C. (200° F.).

FIG. 7 shows the viscosity as a function of time for VES fluidscontaining 1.39 kg/L CaCl2 brine, 6.5 vol % aqueous solution of erucicamidopropyl dimethyl betaine, and 0.2 vol % 2-Butoxyethanol, containingthe internal breaker (1.57M nitric acid solution) at concentrations of0.8 vol %, 1.0 vol %, and 1.2 vol %, respectively at 104° C. (219° F.).

FIG. 8 shows the viscosity as a function of time for VES fluidscontaining 1.39 kg/L CaCl2 brine, 6.5 vol % aqueous solution of erucicamidopropyl dimethyl betaine, 0.2 vol % 2-Butoxyethanol, and 1 vol %1.57M nitric acid with and without the addition of 0.1 vol % acidcorrosion inhibitor at 104° C. (200° F.).

FIG. 9 shows the viscosity as a function of time for a VES fluidcontaining 1.39 kg/L CaCl2 brine, 6.5 vol % aqueous solution of erucicamidopropyl dimethyl betaine, and 0.2 vol % 2-Butoxyethanol with theaddition of the internal breaker 1 (0.52 vol % 3M HCl and 0.13 wt %NaNO3) and the breaker 2 (0.83 vol % 3M HCl and 0.21 wt % NaNO3),respectively, at 104° C. (219° F.).

FIG. 10 shows the viscosity as a function of time for a VES fluidcontaining 1.39 kg/L CaCl2 brine, 6.5 vol % aqueous solution of erucicamidopropyl dimethyl betaine, and 0.2 vol % 2-Butoxyethanol with theaddition of the internal breaker (0.4 vol % 8.3M acetic acid solution)at 104° C. (219° F.).

FIG. 11 shows the viscosity as a function of time for a VES fluidcontaining 1.39 kg/L CaCl2 brine, 6.5 vol % aqueous solution of erucicamidopropyl dimethyl betaine, and 0.2 vol % 2-Butoxyethanol with theaddition of the internal breaker (0.52 vol % 3M HCl solution) at 104° C.(219° F.).

DETAILED DESCRIPTION OF THE INVENTION

For viscosified fluids used in oilfield treatments, it is important thatthere be a mechanism by which the viscosity can be reduced (that is, thefluid can be broken). Typically, breakers are added to the fluid.Typically, the action of the breaker is delayed or requires a triggersuch as crushing of encapsulated breakers, so that the fluid may performits function before the break occurs. Proper placement is an importantfeature for any breaker; it must be with the fluid that is to be broken.Once a fluid invades a formation, most conventional breakers (such asencapsulated oxidizing agents) cannot clean it up. Subsequently addinganother fluid will be inefficient because of the poor fluid-to-fluidcontact.

Oxidizing agents have been tried in the past as breakers for fluidsviscosified with non-polymeric viscosifying agents, but without success.U.S. Patent Application No. 2006-0041028 describes metal-mediatedviscosity reduction of viscoelastic surfactant fluids and states inparagraph [0007] that “Conventional enzymes and oxidizers have not beenfound to act and degrade the surfactant molecules or the viscous micellestructures they form.” U.S. Patent Application No. 2005-0037928 “Methodof Using Viscoelastic Vesicular Fluids to Enhance Productivity ofFormations” discloses vesicular aqueous viscoelastic surfactant basedfluids that contain a surfactant, a quaternary amine polyelectrolyte,and a non-aqueous solvent. In the specification, these materials arerepeatedly distinguished from fluids made with worm-like micelles, suchas those fluids described in U.S. Pat. No. 6,435,277. The applicationdiscloses that the vesicular fluids are sensitive to pH and that theycan be broken in the presence of acid. It further teaches that they maybe broken by oxidative breakers. More specifically, it teaches thatoxidizers may be the only added “breaker” when the fluid is used as adiverter of acid treatments because the fluid will come in contact withacid, but in fracturing fluids the oxidative breaker may only be used incombination with acid-releasing agents, and in fact the acid-releasingagents are suitable breakers alone. In contrast to these teachings, wehave found that oxidizing agents may be used as breakers of VES fluids;the oxidizers are readily soluble in the VES fluid, and the break isactivated by increasing temperature.

The invention will be described primarily in terms of hydraulicfracturing, gravel packing, acidizing, and fracture acidizing, althoughit is to be understood that the invention may be used in many otherways, for example many other oilfield treatments. In hydraulicfracturing, most of the injected fracturing fluid contains a proppantsuch as sand or synthetic ceramic beads, so that when the pressure isreleased the proppant is trapped between the fracture faces and preventsthe fracture from completely closing, thus leaving a flowpath open. Theinjected fracturing fluid is normally viscosified. Increased viscosityresults in formation of a wider fracture, thus a larger flowpath. Aminimal viscosity is also required to transport adequate amounts ofproppant; the actual viscosity required depends primarily upon the fluidflow rate and the density of the proppant. In a typical fracturingprocess, such as hydraulic fracturing with aqueous fluids, the fractureis initiated by first pumping a high viscosity fluid with good tomoderate leak-off properties, and typically no proppant, into theformation. This initial fluid, typically referred to as a “pad”, isusually followed by a second fluid (fracturing fluid) of similarviscosity carrying an initially low concentration and then a graduallyincreasing concentration of proppant into the extended fracture orfractures. The pad initiates and propagates the fracture but does notneed to carry proppant. All the fluids tend to “leak-off” into theformation from the fracture being created or extended. Commonly, by theend of the job the entire volume of the pad will have leaked off intothe formation. This leak-off is determined and controlled by theproperties of the fluid (and additives it may contain, such as fluidloss additives or FLA's), the pumping rate and pressure, and theproperties of the rock. A certain amount of leak-off greater than theminimal possible may be desirable, for example a) if the intention is toplace some fluid in the rock to change the rock properties or to flowback into the fracture during closure, or b) if the intention isdeliberately to cause what is called a “tip screen-out”, or “TSO”, acondition in which the proppant forms a bridge at the some point in thefracture, stopping the lengthening of the fracture and resulting in asubsequent increase in the fracture width. In acid fracturing, thefracture fluid is an acid (or other formation dissolving fluid such as achelant-containing fluid) and the fluid normally does not containproppant; the fracture is held open by asperities in the fracture facescaused by differential etching of the formation material. In matrixacidizing, an acid or other formation dissolving fluid is injected belowfracture pressure and the fluid enters the formation and dissolvesdamaging materials and/or a portion of the formation. Proper leak-offcontrol may be critical to the success of these and other oilfieldtreatments. In these and many other treatment types, after the treatmentit is necessary to decrease the viscosity of the fluid, i.e. to breakthem, and a portion of the fluid in the pores of the formation.

Certain materials may be used as delayed internal breakers forpolymer-free (VES) fluid viscosifiers; the break by the oxidizing agentmay be triggered naturally due to chemical or physical conditions, forexample temperature or pH. It is well known that the decomposition rateconstant of some radical initiators is not only temperature but also pHdependent (See, for example, “Polymer Handbook, Section II,Decomposition Rates of Organic Free Radical Initiators”, J. Brandrup,and E. H. Immergut, Third Edition, Wiley Interscience.) The rate ofdecomposition may also be altered by appropriately selecting acounterion for the oxidizing agent, (e.g. sodium, potassium, andammonium). The break may optionally be accelerated by using redoxactivators, for example sodium metabisulfite, iron (II) sulfate,reducing sugars, for example glucose and others, reducing di andtrisaccharides, and reducing oligo and polysaccharides. The break mayoptionally be delayed, for example by the addition of oxygen scavengers,for example substituted Benzofuranones (for example Ciba SpecialtyChemicals lactone HP-136), hydroxyl amines, trivalent phosphoruscompounds, for example organic phosphites (and phosphonites) such asTNPP, CIBA Specialty Chemicals Irgafox® 168, CIBA Specialty Chemicals,Irgafox® P-EPQ, CIBA Specialty Chemicals, phenolic antioxidants, forexample di tertbutyl alkyl phenols, and others such as those of theIrganox® family such as IRGANOX® L 115, IRGANOX® L 109, IRGANOX® L 107,IRGANOX® L 1010, IRGANOX® L 1035, IRGANOX® L 1076, IRGANOX® L 1081,IRGANOX® L 1098, IRGANOX® L 1135, IRGANOX® L 1330, IRGANOX® L 3114,IRGANOX® L 245, IRGANOX® L 3114, IRGANOX® B 1411, IRGANOX® B 1412,IRGANOX® B 215, IRGANOX® B 220, IRGANOX® B 225, IRGANOX® B 311, IRGANOX®B 561, IRGANOX® B 612, IRGANOX® B 900, IRGANOX® B 921, IRGANOX® E 201,IRGANOX® El 1291, IRGANOX® HP 2215, IRGANOX® HP 2225, IRGANOX® HP 2251,IRGANOX® HP 2341, IRGANOX® HP 2411, IRGANOX® HP 2921, IRGANOX® MD 1024,IRGANOX® PS 800, IRGANOX® PS 802, IRGANOX® XP 320, IRGANOX® XP 420, andIRGANOX® XP 620, trigonox, sulfur compounds such as sodium thiosulfate,hydroquinone, natural antioxidants, for example the natural polyphenols,such as apigenin, resveratrol, ascorbic acid and vitamin C, vitamin E(or alpha-tocopherol), such as IRGANOX® E 201 CIBA Specialty Chemicals,and also by other means if necessary. The break may also optionally betriggered by contact with another fluid, such as another injected fluid,a formation fluid, or a produced fluid such as an acid or basic preflushthat will change the pH of the fluid and therefore change the kineticsof the oxidizer decomposition as well as the effect of the delay agent.Injecting another fluid to promote the break is not normally desirablebecause of potential costs and complexity, but is within the scope ofthe invention. The internal breaking effect occurs whether or not afilter cake is also formed by the addition of a fluid loss additive; thebreaker may also contribute to degradation of the filter cake.

Suitable acidic internal breakers include sulfuric acid; sulfuric acidprecursors such as sulfates, including but not limited to Na₂SO₄ andK₂SO₄ when combined with acids, including but not limited to HCl, alsowill function as the internal breakers for the viscosified fluids in asimilar way as sulfuric acid; suitable acidic internal breakers alsoinclude nitric acid or nitrates in combination with acids, hydrochloricacid or chlorides in combination with acids, and acetic acid or acetatesin combination with acids. For brines containing calcium, magnesium,zinc and other divalent ions, useful acidic internal breakers are suchthat they do not react adversely with these ions to lose breakingfunction. The breakers include nitric acid or nitrates in combinationwith acids, hydrochloric acid or chlorides in combination with acids,and acetic acid or acetates in combination with acids.

Without wishing to be bound by theory, it is believed possible that theacidic internal breaker slowly disrupts inter-micelle and/orintra-micelle (and/or other molecular self-assemblies) binding forcesthat enable the formation and retention of the viscosified fluids.

The acidic internal breakers may cause a decrease in viscosityimmediately or may only do so after the passage of a few minutes orhours, or even many hours, but will still cause a complete break. Thebreaking time may be controlled by selection of the amount and type ofacidic internal breaker to be added to the fluid. Useful amounts ofbreakers depend upon the specific breaker selected, and such factors astemperature of the formation, but typically range from about 0.005 wt %to about 5 wt % of the fluid, preferably from about 0.01 wt % to about 1wt % of the fluid, more preferably from about 0.02 wt % to about 0.5 wt% of the fluid. Time of break is generally reduced at higherpercentages. Temperature can also affect the time required for the fluidto completely break to a water-like viscosity. One skilled in the artcan, by review of the examples and reasonable experimentation, determinewhat ranges are useful for the time of break desired in the operationaltemperature range.

Should it be desirable for the breakers or the breakers to be coated todelay breaking action, the coating can be done by any known process. Twomain types of coating process, top spray and bottom spray, arecharacterized by the location of the spray nozzle at the bottom or thetop of a fluidized bed of solid particles. The nozzle sprays an atomizedflow of coating solution while the particles are suspended in thefluidizing air stream that carries the particles past the spray nozzle.The particles then collide with the atomized coating material as theyare carried away from the nozzle in a cyclic flow. The temperature ofthe fluidizing air is set to evaporate solution or suspension liquidmedia or solidify the coating material shortly after colliding with theparticles. The solidified coating materials will cover the particlesgradually. This process is continued until each particle is coateduniformly to the desired coating thickness.

The properties of such coated particles can be tuned with the coatingformulation, processing conditions, and layering with different coatingmaterials. The choice of material will depend on a variety of factorssuch as the physical and chemical properties of the material beingemployed. Coating material can be from one of these categories: aqueousand organic solutions, dispersions, and hot melts. Non-limiting examplesinclude acrylics, halocarbon, polyvinyl alcohol, Aquacoat® aqueousdispersions, hydrocarbon resins, polyvinyl chloride, Aquateric® entericcoatings, HPC, polyvinylacetate phthalate, HPMC, polyvinylidenechloride, HPMCP, proteins, Kynar®, fluoroplastics, rubber (natural orsynthetic), caseinates, maltodextrins, shellac, chlorinated rubber,silicone, Coateric® coatings, microcrystalline wax, starches, coatingbutters, milk solids, stearines, Daran® latex, molasses, sucrose,dextrins, nylon, surfactants, Opadry® coating systems, Surelease®coating systems, enterics, Paraffin wax, Teflon® fluorocarbons,Eudragits® polymethacrylates, phenolics, waxes, ethoxylated vinylalcohol, vinyl alcohol copolymer, polylactides, zein, fats, polyaminoacids, fatty acids, polyethylene gelatin, polyethylene glycol,glycerides, polyvinyl acetate, vegetable gums and polyvinyl pyrrolidone.

The invention is particularly suited for use with polymer free fluids.The invention is especially useful in gravel packing and the like, wherenear-wellbore damage is often a particularly serious problem. Theinvention makes it possible to treat wells previously eliminated ascandidates due to the low fluid efficiency (high leak-off) that wouldhave been expected. The acidic internal breakers may be used as analternative to fluid loss additives, especially when filter cakes areundesirable; instead of minimizing fluid loss, the fluid loss may beaccepted and the leaked-off fluid broken. Viscosified fluids containingacidic internal breakers may also function as a self-destructingdiverting agent. They may also be used in kill pills, which can bedifficult to break because mechanisms often available for breaking (suchas crushing of encapsulated materials, or later addition of anothercomponent) cannot be used with kill pills.

In treatments that typically include multiple stages, such as mosthydraulic fracturing, acid fracturing, frac-packing, and gravel packingembodiments, the acidic internal breaker may be added in the pad,throughout the treatment or to only some of the stages, such as some ofthe proppant, gravel, acid, or diversion stages. The acidic internalbreakers are particularly useful in hydraulic fracturing, frac-packing,and gravel packing because mechanical removal methods are impossible andmethods involving contacting the additive with an additional fluid arenot always practical. The compositions and methods of the invention arealso particularly useful in cases where it is desirable to allow acertain amount of treatment fluid to enter the formation, for examplefor the purpose of altering formation wettability or oil or watersaturation.

Treatment fluids used with the compositions and methods of the inventiontypically also contain other materials such as demulsifiers, corrosioninhibitors, friction reducers, clay stabilizers, scale inhibitors,biocides, mutual solvents, surfactants, anti-foam agents, defoamers,viscosity stabilizers, iron control agents, diverters, emulsifiers,foamers, oxygen scavengers, pH control agents, buffers, and the like.Compatibility of acidic internal breakers with such additives should bechecked in the laboratory. The treatments of the Invention are conductednormally; the treatment fluid and additives are transported to the site,mixed, stored, and pumped in the usual ways for the respectivechemicals. When resin coated proppants (RCP's) are used, testing shouldbe done to ensure that the RCP's and acidic internal breakers arecompatible and that neither one interferes with the performance of theother; conventional natural and synthetic proppants and gravels maynormally be used without testing.

The invention is carried out by considering information about the well,the formation, the fluids and additives available, and criteria for asuccessful treatment, and preparing an optimized plan for maximizingtreatment performance according to the data and the criteria. This isusually done by analyzing the well using treatment design and evaluationsoftware; for example, in hydraulic fracturing software, pressuregradients are combined with fracture length and height evolutionalgorithms, complete leak-off information, and the effects of multiplefluid injections and their temperature changes.

The optimal concentration of the acidic internal breaker can bedetermined by choosing the breaking time and rate and measuring thebreak with samples of the intended fluids under the intended formationconditions. The preferred concentration of acidic internal breakers isfrom about 0.005 weight % to about 10 weight %, more preferred is in therange of about 0.01 weight % to about 5 weight %, and most preferred isin the range of about 0.02 weight % to about 0.5 weight %. (It should beunderstood that throughout this specification, when we list or describea concentration or amount range as being useful, or suitable, or thelike, we intend that any and every concentration within the range,including the end points, is to be considered as having been stated.Furthermore, each numerical value should be read once as modified by theterm “about” (unless already expressly so modified) and then read againas not so modified unless otherwise stated in context. For example, “arange of from 1 to 10” is to be read as indicating each and everypossible number along the continuum between about 1 and about 10. Inother words, when we express a certain range, even if we explicitlyidentify or refer to only a few specific data points within the range,or even to no data points within the range, it is to be understood thatthe inventors appreciate and understand that any and all data pointswithin the range are to be considered to have been specified, and thatthe inventors have possession of the entire range and all points withinthe range.) Measurement, prediction, and control of breaking arefamiliar to those of ordinary skill in the arts of well stimulation andsand control.

If fluid loss additives are used, it is preferable, although notnecessary, to use completely degradable fluid loss additives.Particularly desirable FLA's would be the “internal filter cake/matrixbreaker” materials disclosed in copending U.S. patent application Ser.No. 11/532,553, entitled “Internal Breaker for Oilfield Treatments,”inventors Jesse Lee, Philip Sullivan, Erik Nelson, Yiyan Chen, CarlosAbad, Belgin Baser, and Lijun Lin, filed Sep. 18, 2006. When the pad andthe fracture fluid are polymer-free and any fluid loss additive is fullydegradable, neither the near-wellbore formation nor the proppant bedleft in the fracture after the job contains deleterious polymers orsolids, as would be the case if the fracture fluid contained any polymeror if the fluid loss additive was not fully degradable. Thereforefracture conductivity is high and skin is low.

Any non-polymeric fluid, for example VES based fluid, that is compatiblewith the formation, the formation fluids, and the other components ofthe fluid, can be used in the Invention. Particularly effectivenon-limiting examples of fluids are those described in U.S. Pat. Nos.5,551,516; 5,964,295; 5,979,555; 5,979,557; 6,140,277; 6,435,277; and6,258,859, all of which are hereby incorporated by reference.Vesicle-based fluids may be used, such as those described in U.S. Pat.No. 6,509,301, also hereby incorporated herein by reference.

In some cases, a certain amount of leak-off is desired, for example sothat a tip screen-out occurs in fracturing, a condition in which theproppant forms a bridge, preferably at the end of the fracture away fromthe wellbore, stopping the lengthening of the fracture and resulting ina subsequent increase in the fracture width. For example, hydraulicfracturing followed by gravel-packing in a single operation, sometimescalled a frac-pac, fracpac, frac pac, frac and pac, or StimPac,sometimes with a deliberate tip screen-out to generate a short widefracture, is usually performed in relatively high permeabilityformations for sand-control purposes. However, such operations aresometimes performed in low permeability formations, occasionally forsand control, but also for other reasons, for example to bypasspermeability damage near the wellbore caused by scaling or to improveupon poor communication between the wellbore and the formation or aprevious fracture, or in formations in which perforating createsdamaging fines, or for other reasons. Such jobs designed to generateshort wide fractures may also be performed without subsequentgravel-packing when sand control is not an issue. The methods of thepresent Invention can be used in any of these cases (fracturing followedby gravel packing and/or fracturing for short wide fractures, in eithercase with or without deliberate tip screen-out).

The acid used in the matrix acidizing and acid fracturing methods ofthis invention can be any acid used in acid fracturing, includinggelled, self-diverting, and delayed acids. Commonly used, but notlimiting, acids are hydrochloric, hydrofluoric, fluoboric, acetic, andformic acids and mixtures thereof, and those acids in the form of oilexternal emulsions (for reaction rate retardation), or oil internalemulsions (for hydrocarbon solvency). The acids can contain additivessuch as corrosion inhibitors and chelants used to help dissolve rockcomponents and keep them in solution. Gelled, self-diverting, anddelayed acids can be gelled with suitable VES's.

Although in conventional propped fracturing the most common way tocontrol fluid loss is to build an impermeable or reduced-permeabilityfiltercake on the fracture walls (faces), in acid fracturing, especiallywith a low viscosity ungelled acid, pad viscosity is important for fluidloss control. On the other hand, if the acid is viscosified with a VESsystem, then if the VES has higher low-shear viscosity than high-shearviscosity, which is common, then as the VES leaks off a short distanceinto the formation, the flow rate decreases, the shear rate thereforedecreases, and the fluid becomes more viscous. Such effects can reducelow viscosity ungelled acid leak-off better than a wallbuilding systemthat dissolves or decomposes in acid. In these cases, an acidic internalbreaker would be particularly suitable in the pad. This allows acidtreatment a certain selected depth into the formation and the acid thenperforms the very desirable function of diverting subsequent acid.Similarly, some acidic internal breakers may be used with viscoelasticdiverting acids, which are acids containing certain viscoelasticsurfactants, such that the fluid has low viscosity as formulated andinjected, but increases in viscosity as the acid reacts with theformation, such as a carbonate. Examples of such systems were describedin U.S. Pat. Nos. 6,399,546, 6,667,280, and 7,028,775 and U.S. PatentApplication No. 2003-0119680, all hereby incorporated by reference.

Sometimes acid fracturing is performed with a series of alternating pad,acid, pad, acid, etc. stages in order to optimize coverage. The firstnon-acidic pad initiates a fracture for the first acid stage to follow.That first acid stage etches a portion of the fracture face. Subsequentstages of pad and acid repeat the process until the designed treatmentvolumes have been injected and the desired fracture has been created. Inthe past, this process has always used a gelled pad, such as onecontaining a viscoelastic surfactant system. The acidic internal breakerof the Invention may be used in at least the first pad and sometimes inall the pad stages. Similarly, matrix acidizing may be performed withalternating stages of acid and another fluid, such as a diverter, someor all of which may be viscosified; the acidic internal breaker of theInvention may be included in some or all of either the acid or the otherfluid to break a viscosifier.

The acidic internal breakers of the invention may be added to a wellborefluid by metering them in to the base water fluid as a concentratedliquid. If the material is received as an emulsion, dispersion, orslurry, it can be stored in that form and used in that form directly. Ifit is received in dry form (for example as a solid dispersible powder offine particles or as a dry emulsion) the particles can be pre-dispersedin water or brine as required and metered in as a liquid stream, oralternatively they may be added as solids to the base fluid stream.

The reactivity of a given acidic internal breaker at a particulartemperature and in contact with a viscosified fluid or fluids of aparticular composition (for example pH and the concentration and natureof other components, especially electrolytes), is readily determined bya simple experiment: exposing the fluid or fluids to the acidic internalbreaker under treatment conditions and monitoring the viscosity.

Although the acidic internal breakers of this Invention may be used withVES's made with any type of surfactant, or mixtures of surfactants, withor without one or more co-surfactants, and with or without otheradditives intended to stabilize or modify the properties of the micellesor vesicles (such as buffers, shear recovery additives, salts, andrheology boosters). Preferred VES's are cationic, anionic, amphoteric,and zwitterionic. Suitable VES's, for example, are described in thefollowing U.S. Patents, all of which are hereby incorporated in theirentirety: U.S. Pat. Nos. 5,964,295; 5,979,557; 6,306,800; 6,637,517; and6,258,859. The viscoelastic surfactant may be, for example, of thefollowing formulae: R—Z, where R is the hydrophobic tail of thesurfactant, which is a fully or partially saturated, linear or branchedhydrocarbon chain of at least 14 carbon atoms and Z is the head group ofthe surfactant which may be for example —NR₁R₂R₃ ⁺, —SO₃ ⁻, COO⁻ or, inthe case where the surfactant is zwitterionic, —N⁺(R₁)(R₂)R₃—COO⁻ whereR₁, R₂ and R₃ are each independently hydrogen or a fully or partiallysaturated, linear or branched, aliphatic chain of at least one carbonatom; and where R₁ or R₂ may comprise a hydroxyl terminal group.

Cleavable viscoelastic surfactants, for example of the followingformula, may be used, as disclosed in International Patent ApplicationWO02/064945: R—X—Y—Z, where R is the hydrophobic tail of the surfactant,which is a fully or partially saturated, linear or branched hydrocarbonchain of at least 18 carbon atoms, X is the cleavable or degradablegroup of the surfactant which is an acetal, amide, ether or ester bond,Y is a spacer group which is a short saturated or partially saturatedhydrocarbon chain of n carbon atoms where n is at least equal to 1,preferably 2 and, when n is equal to or greater than 3, the chain may bea straight or branched saturated or partially saturated chain, and Z isthe head group of the surfactant which can NR₁R₂R₃ ⁺, —SO₃ ⁻, COO⁻ or,in the case where the surfactant is zwitterionic, —N⁺(R₁R₂R₃—COO⁻) whereR₁, R₂ and R₃ are each independently hydrogen or a fully or partiallysaturated, linear or branched, aliphatic chain of at least one carbonatom, possibly comprising a hydroxyl terminal group. Due to the presenceof the cleavable or degradable group, cleavable surfactants are able todegrade under downhole conditions.

A nonlimiting example of a suitable cationic viscoelastic surfactantuseful for the implementation of the Invention isN-erucyl-N,N-bis(2-hydroxyethyl)-N-methyl ammonium chloride. Nonlimitingexamples of some suitable anionic viscoelastic surfactants useful forthe implementation of the Invention are monocarboxylates RCOO⁻ such asoleate where R is C₁₇H₃₃ or di- or oligomeric carboxylates such as thosedisclosed in International Patent Application WO 02/11874.

The acidic breakers of this invention have been found to be particularlyuseful breakers when used with several types of zwitterionicsurfactants. In general, suitable zwitterionic surfactants have theformula:RCONH—(CH₂)_(n)(CH₂CH₂O)_(m)(CH₂)_(b)—N⁺(CH₃)₂—(CH₂)_(a′)(CH₂CH₂O)_(m′)(CH₂)_(b′)COO⁻in which R is an alkyl group that contains from about 11 to about 23carbon atoms which may be branched or straight chained and which may besaturated or unsaturated; a, b, a′, and b′ are each from 0 to 10 and mand m′ are each from 0 to 13; a and b are each 1 or 2 if m is not 0 and(a+b) is from 2 to about 10 if m is 0; a′ and b′ are each 1 or 2 when m′is not 0 and (a′+b′) is from 1 to about 5 if m is 0; (m+m′) is from 0 toabout 14; and CH₂CH₂O may also be oriented as OCH₂CH₂. Preferredsurfactants are betaines and amidoamine oxides.

Two examples of betaines are oleylamidopropyl dimethyl betaine anderucylamidopropyl dimethyl betaine. Oleylamidopropyl dimethyl betainecontains an oleyl acid amide group (including a C₁₇H₃₃ alkene tailgroup); erucylamidopropyl dimethyl betaine contains an erucic acid amidegroup (having a C₂₁H₄₁ tail group). Betaine surfactants, and others thatare suitable, are described in U.S. Pat. No. 6,258,859.

Although the invention has been described throughout using the term“VES”, or “viscoelastic surfactant” to describe the non-polymericviscosified aqueous fluid, any non-polymeric material may be used toviscosify the aqueous fluid provided that the requirements describedherein for such a fluid are met, for example the required viscosity,stability, compatibility, and lack of damage to the wellbore, formationor fracture face. Examples, without regard to whether they form, or aredescribed as forming, vesicles or viscoelastic fluids, include, but arenot limited to, those viscosifiers described in U.S. Pat. No. 6,035,936and in GB application No. 2,366,307A.

Also optionally, fracturing fluids may contain materials designed toassist in proppant transport and/or to limit proppant flowback after thefracturing operation is complete by forming a porous pack in thefracture zone. Such materials can be any known in the art, such as areavailable from Schlumberger under the tradename PropNET™ (for examplesee U.S. Pat. No. 5,501,275). Exemplary proppant flowback inhibitorsinclude fibers or platelets of novoloid or novoloid-type polymers (U.S.Pat. No. 5,782,300).

The choice of acidic internal breaker is based primarily on the desiredtime before the delayed break, which will depend upon the choice andconcentration of VES and the temperature, and may depend upon the sizeof the job, the nature of the job, and other factors known to those ofordinary skill in the art. Similarly, appropriate delay agents oraccelerating agents and their concentrations may be determined by simplelaboratory experiments, for example mixing all the components, heatingto the job temperature, and monitoring the viscosity. A requirement iscompatibility of the water with the VES system and with the acidicinternal breaker. The system comprising an acidic internal breaker alsoworks with VES systems that contain co-surfactants or other additivescommonly included in oilfield treatment fluids. Again, a requirement iscompatibility of the acidic internal breaker, the VES system, and theother components. The fluid containing an acidic internal breaker may bebatch-mixed or mixed on-the-fly.

Any additives normally used in such treatments may be included, againprovided that they are compatible with the other components and thedesired results of the treatment. Such additives can include, but arenot limited to, corrosion inhibitors, delay agents, biocides, buffers,fluid loss additives, etc. The wellbores treated can be vertical,deviated or horizontal. They can be completed with casing andperforations or open hole.

In gravel packing, or combined fracturing and gravel packing, it iswithin the scope of the Invention to apply the compositions and methodsof the Invention to treatments that are done with or without a screen.Although treatments are normally done to promote hydrocarbon production,it is within the scope of the Invention to use the compositions andmethods of the invention in wells intended for the production of otherfluids such as carbon dioxide, water or brine, or in injection wells.Although we have described the Invention in terms of unfoamed fluids,fluids foamed or energized (for example with nitrogen or carbon dioxideor mixtures thereof) may be used. Adjustment of the appropriateconcentrations due to any changes in the fluid properties (or otherparameters, such as proppant concentration) consequent to foaming wouldbe made.

EXAMPLES

Base Fluids: All fluids were evaluated in a Fann50-type Rheometer orBohlin Rheometer. This instrument requires about 5-20 minutes to reachtest temperature, so that the early portion of the data reflects heatingto the final temperature. The instrument sometimes showed small regularfluctuations around the intended temperature, so small oscillations inthe observed viscosities in some figures reflect that occurrence. Astandard procedure is used for the Fann50 measurements, where theviscosity is measured at a shear rate of 100 s⁻¹ with ramps down to 75s⁻¹, 50 s⁻¹ and 25 s⁻¹ every 15 min. A heating time of 15 or 30 min wasapplied for the fluid to reach the test temperature. More accurateviscosity measurements were obtained on the Bohlin rheometers over ashear rate range between 0.01 s⁻¹ and 100 s¹. Note that fluctuations inviscosities obtained on Bohlin rheometers are generally signatures ofvery low, water-like viscosities, where the equipment limitations arereached.

Experiments were performed in which a viscoelastic fluid was heated toand held, usually at 104° C. (219° F.) or 93.3° C. (200° F.), with andwithout breakers and other additives as noted.

Base Fluid in 1.39 kg/L CaCl2 brine at 104° C. (219° F.).

FIG. 1 shows a base VES fluid consisting of 1.39 kg/L CaCl2 brine, 6.5vol % aqueous solution of erucic amidopropyl dimethyl betaine, and 0.2vol % 2-Butoxyethanol. The plot shows VES with no other additive.

Example 1

This Example demonstrates the use of sulfuric acid as an acidic internalbreaker. The changes in the viscosity over time of a VES fluidcontaining 1.43 kg/L NaBr brine, 6.5 vol % of an aqueous solution oferucic amidopropyl dimethyl betaine, and 0.2 vol % 2-Butoxyethanol, andcontaining a sulfuric acid internal breaker (3M sulfuric acid solution)at concentrations of 0 (served as the baseline), 0.1 vol %, and 0.15 vol%, respectively, at 104° C. (219° F.) were measured and as shown in FIG.2, the breaking time is tunable by varying the breaker concentration; asthe concentration of the breaker increased, the breaking time decreasedconsistently.

Example 2

This Example demonstrates that the viscoelastic fluid formula can beadjusted according to the fluid requirement. The viscosity changes overtime of the base VES fluid containing 1.43 kg/L NaBr brine, 6.5 vol %aqueous solution of erucic amidopropyl dimethyl betaine, and containing0.2 vol % aqueous solution of alkyl (C12-16) dimethyl benzyl ammoniumchloride in place of the 2-butoxyethanol was also broken using theinternal breaker (3M sulfuric acid solution) at concentrations of 0.075vol % and 0.1 vol %, respectively, at 104° C. (219° F.). As can be seenin FIG. 3, the breaking time decreased with increased breakerconcentration consistently for this composition as well.

Example 3

This Example demonstrates that the concentration of the viscosifier inthe fluid can be varied. A group of gels prepared from 1.43 kg/L NaBr, 8vol % aqueous solution of erucic amidopropyl dimethyl betaine, andvarious concentrations of internal breaker (3M sulfuric acid solution),0-0.2 vol %, were tested. In FIG. 4, the representative rheology curvesare shown for gels containing the breaker at concentrations of 0 (as thebaseline), 0.11 vol %, and 0.15 vol %, respectively. Again, as theconcentration of the breaker increased, the breaking time decreasedconsistently

Example 4

Sand settling tests were carried out at 93° C. with 0.48 kg of Econo30/50 proppant added per liter of fluid in a 500 ml graduated cylinder.The gel used in the sand settling tests was prepared with 1.43 kg/L NaBrbrine, 8 vol % aqueous solution of erucic amidopropyl dimethyl betaine,and containing the sulfuric acid internal breaker (3M sulfuric acidsolution) at the concentration of 0.125 vol %. The time taken to reach20% settled sand was between 50 and 60 minutes, which is consistent withthe Bohlin test results. FIG. 5 shows the shear rate vs. time for thesefluids.

Example 5

This Example uses D-isoascorbic acid as the internal acidic breaker.FIG. 6 shows the viscosity as a function of shear rate for a VES fluidcontaining 1.43 kg/L NaBr and 6 vol % aqueous solution of erucicamidopropyl dimethyl betaine, containing 0.10 and 0.25 wt % ofD-isoascorbic acid as the internal breaker at 100° C. (212° F.). In FIG.6, the gel containing 0.25 wt % of the breaker has a much shorterbreaking time, showing that breaking time can be adjusted by varying theD-isoascorbic acid concentration. Viscosity reduction or breaking wasalso observed when 2 wt % KCl was used as the brine.

Example 6

This Example demonstrates the use of acidic internal breakers in calciumion (Ca²⁺) containing brines. The fluids mentioned in this section areprepared with brines that contain Ca2+ ions. The brines include, but notlimited to CaCl2, CaBr2, and the combinations. FIG. 7 shows theviscosity as a function of time at for VES fluids containing 1.39 kg/LCaCl2, 6.5 vol % aqueous solution of erucic amidopropyl dimethylbetaine, and 0.2 vol % 2-Butoxyethanol, and containing the acidicinternal breaker (1.57M nitric acid solution) at concentrations of 0.8vol %, 1.0 vol %, and 1.2 vol %, respectively at 104° C. (219° F.). Asthe concentration of the acidic internal breaker was increased, thebreaking time decreased consistently.

Example 7

This Example demonstrates that the gel formula was found to becompatible with acid corrosion inhibitors. In the example shown in FIG.8, one gel was prepared with 1.39 kg/L CaCl2 brine, 6.5 vol % aqueoussolution of erucic amidopropyl dimethyl betaine, 0.2 vol %2-Butoxyethanol, and 1 vol % 1.57M nitric acid solution as the internalbreaker. The other gel has the same composition plus 0.1 vol % selectedacid corrosion inhibitor, a typical dosage for this corrosion inhibitor.The rheology curves of the two gels tested with Fann50 at 104° C. (219°F.) nearly trace each other in FIG. 8, suggesting that the inhibitor hasno obvious adverse effect on the fluid property.

Example 8

This Example demonstrates that nitrates combined with acids, canfunction as the acidic internal breakers for fluids in a similar way asnitric acid. In the example shown in FIG. 9, gels were prepared with1.39 kg/L CaCl2 brine, 6.5 vol % aqueous solution of erucic amidopropyldimethyl betaine, and 0.2 vol % 2-butoxyethanol. One gel contained theinternal breaker 1 consisting of 0.52 vol % 3M HCl and 0.13 wt % NaNO3,and the other gel contained the breaker 2 consisting of 0.83 vol % 3MHCl and 0.21 wt % NaNO3. The rheology curves of the two gels were testedwith Fann50 at 104 deg C., showing that the higher dose of breaker(breaker 2) leads to faster breaking time.

Example 9

This Example demonstrates the use of acidic internal breakers in calciumion (Ca²⁺) containing brines. The fluids mentioned here are preparedwith brines that contain Ca2+ ions. FIG. 10 shows the viscosity as afunction of time at for VES fluids containing 1.39 kg/L CaCl2, 6.5 vol %aqueous solution of erucic amidopropyl dimethyl betaine, and 0.2 vol %2-butoxyethanol, and containing the acidic internal breaker (8.33Macetic acid solution) at the concentration of 0.4 vol % at 104° C. (219°F.).

Example 10

This Example demonstrates the use of acidic internal breakers in calciumion (Ca²⁺) containing brines. The fluids mentioned here are preparedwith brines that contain Ca2+ ions. FIG. 11 shows the viscosity as afunction of time at for VES fluids containing 1.39 kg/L CaCl2, 6.5 vol %aqueous solution of erucic amidopropyl dimethyl betaine, and 0.2 vol %2-butoxyethanol, and containing the acidic internal breaker (3M HClsolution) at the concentration of 0.52 vol % at 104° C. (219° F.).

Example 11

This Example demonstrates that polythionates including sodiumtetrathionate dehydrate (Na2S4O6.2H2O) can be used as a latent acidinternal breaker for VES fluids. Decomposition of sodium tetrathionategenerates acidic species when the gel is broken. Viscosity of similarVES fluids can be gradually reduced over time and that the break timecan be well controlled by the tetrathionate concentration at a giventemperature.

It should be understood that only a few examples have been shown for theuse of tested breakers with a specific VES, at specific concentrations,in specific brines, at specific temperatures, and with or withoutspecific accelerators and retarders at specific concentrations. The factthat a specific breaker was observed to be suitable or not in a specificcase should not be taken as being a general conclusion for that breaker.It is believed that all breakers will be suitable under certainconditions. As usual, laboratory testing should be done to determine theoptimal use parameters for each breaker in each fluid at each condition.

The present invention may be embodied in other specific forms withoutdeparting from its spirit or essential characteristics. The describedembodiments are to be considered in all respects only as illustrativeand not restrictive. The scope of the invention is, therefore, indicatedby the appended claims rather than by the foregoing description. Allchanges which come within the meaning and range of equivalency of theclaims are to be embraced within their scope. Reference throughout thisspecification to features, advantages, or similar language does notimply that all of the features and advantages that may be realized withthe present invention should be or are in any single embodiment of theinvention. Rather, language referring to the features and advantages isunderstood to mean that a specific feature, advantage, or characteristicdescribed in connection with an embodiment is included in at least oneembodiment of the present invention. Thus, discussion of the featuresand advantages, and similar language, throughout this specification may,but do not necessarily, refer to the same embodiment. Furthermore, thedescribed features, advantages, and characteristics of the invention maybe combined in any suitable manner in one or more embodiments.

What is claimed is:
 1. An oilfield treatment composition comprising anaqueous fluid, a non-polymeric viscosifier, a corrosion inhibitor, afree radical propagating agent selected from the group consisting ofmetabisulfites, and reducing tri-, oligo- and poly-saccharides, and anacidic internal breaker, wherein said acidic internal breaker is presentin an amount of from about 0.01 wt % to about 1 wt % of the oilfieldtreatment composition, and is a delayed internal breaker that is capableof reducing viscosity of a well fluid that is present inside asubterranean formation.
 2. The composition of claim 1 further comprisinga brine, wherein said brine contains substantially only monovalent ionsselected from the group consisting of KBr, NaBr, KCl, CsCl, CsBr, Naformate, K Formate, Cs Formate and NaCl.
 3. The composition of claim 1wherein said acidic internal breaker is selected from the groupconsisting of sulfuric acid, sulfurous acid, methanesulfonic acid, andan acid resulting from the disassociation of a polythionate.
 4. Thecomposition of claim 1 further comprising a brine, wherein said brineincludes at least one divalent ion selected from the group consisting ofCaBr₂, ZnCl₂, ZnBr₂, and CaCl₂.
 5. The composition of claim 4 whereinthe acidic internal breaker is nitric acid.
 6. The composition of claim1 wherein the free radical propagating agent is selected from the groupconsisting of metabisulfites.
 7. The composition of claim 1 wherein saidnon-polymeric viscosifier comprises a viscoelastic surfactant selectedfrom the group consisting of zwitterionic surfactants and cationicsurfactants.
 8. The composition of claim 7 wherein said zwitterionicsurfactant comprises a betaine.
 9. The composition of claim 7 whereinsaid viscoelastic surfactant comprises an amine oxide surfactant. 10.The composition of claim 1 wherein said acidic internal breaker isselected from the group consisting of hydrochloric acid, and phosphoricacid.
 11. The composition of claim 1 further comprising a shear recoveryadditive.
 12. The composition of claim 1 wherein the free radicalpropagating agent is selected from the group consisting of reducingtrisaccharides.
 13. The composition of claim 1 wherein the free radicalpropagating agent is sodium metabisulfite.
 14. The composition of claim1 wherein the free radical propagating agent is selected from reducingpolysaccharides.